Noise reduction in a particle motion sensing seismic streamer

ABSTRACT

An apparatus includes particle motion sensors and a streamer that contains the particle motion sensors. The streamer is towed in connection with a seismic survey, and the towing of the streamer produces a turbulent flow. The streamer includes an inner cable and a fluid containing layer. The inner cable includes a material to circumscribe and extend along a longitudinal axis of the streamer and circumscribe at least one of the particle motion sensors. The fluid containing layer surrounds the inner cable to reduce noise that is otherwise sensed by the particle motion sensors due to the turbulent flow.

This application is a continuation of U.S. patent application Ser. No.12/426,007 filed on Apr. 17, 2009, which claims priority to U.S.Provisional Application No. 61/130,216 filed on May 29, 2008, the entirecontents of which are hereby incorporated by reference herein.

BACKGROUND

The invention generally relates to noise reduction in a particle motionsensing seismic streamer.

Seismic exploration involves surveying subterranean geologicalformations for hydrocarbon deposits. A survey typically involvesdeploying seismic source(s) and seismic sensors at predeterminedlocations. The sources generate seismic waves, which propagate into thegeological formations creating pressure changes and vibrations alongtheir way. Changes in elastic properties of the geological formationscatter the seismic waves, changing their direction of propagation andother properties. Part of the energy emitted by the sources reaches theseismic sensors. Some seismic sensors are sensitive to pressure changes(hydrophones), others to particle motion (e.g., geophones), andindustrial surveys may deploy only one type of sensors or both. Inresponse to the detected seismic events, the sensors generate electricalsignals to produce seismic data. Analysis of the seismic data can thenindicate the presence or absence of probable locations of hydrocarbondeposits.

Some surveys are known as “marine” surveys because they are conducted inmarine environments. However, “marine” surveys may be conducted not onlyin saltwater environments, but also in fresh and brackish waters. In onetype of marine survey, called a “towed-array” survey, an array ofseismic sensor-containing streamers and sources is towed behind a surveyvessel.

SUMMARY

In an embodiment of the invention, an apparatus includes particle motionsensors and a streamer that contains the particle motion sensors. Thestreamer is towed in connection with a seismic survey, and the towing ofthe streamer produces a turbulent flow. The streamer includes an innercable and a fluid containing layer. The inner cable includes a materialto circumscribe and extend along a longitudinal axis of the streamer andcircumscribe at least one of the particle motion sensors. The fluidcontaining layer surrounds the inner cable to reduce noise that isotherwise sensed by the particle motion sensors due to the turbulentflow.

In another embodiment of the invention, a technique includes providingparticle motion sensors in a streamer to acquire particle motionmeasurements; and suppressing noise otherwise acquired in the particlemotion measurements. The suppressing includes surrounding an inner cablethat includes material to circumscribe and extend along a longitudinalaxis of the streamer; and circumscribing at least one of the particlemotion sensors with a fluid containing layer that moves with thestreamer. The fluid containing layer surrounds the inner cable to reducenoise otherwise sensed by the particle motion sensors due to theturbulent flow.

Advantages and other features of the invention will become apparent fromthe following drawing, description and claims.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a schematic diagram of a marine seismic acquisition systemaccording to an embodiment of the invention.

FIGS. 2, 4 and 5 depict partial schematic diagrams of a streamer inaccordance with embodiments of the invention.

FIG. 3 is a cross-sectional view taken along line 3-3 of FIG. 2according to an embodiment of the invention.

FIG. 6 is a flow diagram depicting a technique to reduce noise acquiredby particle motion sensors according to an embodiment of the invention.

FIG. 7 is a cross-sectional view of a well according to an embodiment ofthe invention.

DETAILED DESCRIPTION

FIG. 1 depicts an embodiment 10 of a marine-based seismic dataacquisition system in accordance with some embodiments of the invention.In the system 10, a survey vessel 20 tows one or more particle motionsensing seismic streamers 30 (one exemplary streamer 30 being depictedin FIG. 1) behind the vessel 20. It is noted that the streamers 30 maybe arranged in a spread in which multiple streamers 30 are towed inapproximately the same plane at the same depth. As another non-limitingexample, the streamers may be towed at multiple depths, such as in anover/under spread, for example.

The seismic streamers 30 may be several thousand meters long and maycontain various support cables (not shown), as well as wiring and/orcircuitry (not shown) that may be used to support communication alongthe streamers 30. In general, each particle motion sensing seismicstreamer 30 includes seismic sensors 58, which include particle motionsensors as well as hydrophones to acquire pressure data. In someembodiments of the invention, the seismic sensors 58 may bemulti-component sensors, with each sensor being capable of detecting apressure wavefield and at least one component of a particle motion thatis associated with acoustic signals that are proximate to the sensor.Examples of particle motions include one or more components of aparticle displacement, one or more components (inline (x), crossline (y)and vertical (z) components (see axes 59, for example)) of a particlevelocity and one or more components of a particle acceleration.

Depending on the particular embodiment of the invention, the hydrophonesmay be embedded in the core (inner cable) of the streamer, mounted in arecession of the inner cable, or disposed in the fluid layer, as just afew non-limiting examples.

Depending on the particular embodiment of the invention, themulti-component seismic sensor may include one or more hydrophones,geophones, particle displacement sensors, particle velocity sensors,accelerometers, pressure gradient sensors, or combinations thereof.

For example, in accordance with some embodiments of the invention, aparticular multi-component seismic sensor may include a hydrophone formeasuring pressure and three orthogonally-aligned accelerometers tomeasure three corresponding orthogonal components of particle velocityand/or acceleration near the sensor. It is noted that themulti-component seismic sensor may be implemented as a single device (asdepicted in FIG. 1) or may be implemented as a plurality of devices,depending on the particular embodiment of the invention. A particularmulti-component seismic sensor may also include pressure gradientsensors, which constitute another type of particle motion sensors. Eachpressure gradient sensor measures the change in the pressure wavefieldat a particular point with respect to a particular direction. Forexample, one of the pressure gradient sensors may acquire seismic dataindicative of, at a particular point, the partial derivative of thepressure wavefield with respect to the crossline direction, and anotherone of the pressure gradient sensors may acquire a particular point,seismic data indicative of the pressure data with respect to the inlinedirection.

The marine seismic data acquisition system 10 includes seismic sources40 (two exemplary seismic sources 40 being depicted in FIG. 1), such asair guns and the like. In some embodiments of the invention, the seismicsources 40 may be coupled to, or towed by, the survey vessel 20.Alternatively, in other embodiments of the invention, the seismicsources 40 may operate independently of the survey vessel 20, in thatthe sources 40 may be coupled to other vessels or buoys, as just a fewexamples.

As the seismic streamers 30 are towed behind the survey vessel 20,acoustic signals 42 (an exemplary acoustic signal 42 being depicted inFIG. 1), often referred to as “shots,” are produced by the seismicsources 40 and are directed down through a water column 44 into strata62 and 68 beneath a water bottom surface 24. The acoustic signals 42 arereflected from the various subterranean geological formations, such asan exemplary formation 65 that is depicted in FIG. 1.

The incident acoustic signals 42 that are created by the sources 40produce corresponding reflected acoustic signals, or pressure waves 60,which are sensed by the seismic sensors 58. It is noted that thepressure waves that are received and sensed by the seismic sensors 58include “up going” pressure waves that propagate to the sensors 58without reflection, as well as “down going” pressure waves that areproduced by reflections of the pressure waves 60 from an air-waterboundary 31.

The seismic sensors 58 generate signals (digital signals, for example),called “traces,” which indicate the acquired measurements of thepressure wavefield and particle motion. The traces are recorded and maybe at least partially processed by a signal processing unit 23 that isdeployed on the survey vessel 20, in accordance with some embodiments ofthe invention. For example, a particular seismic sensor 58 may provide atrace, which corresponds to a measure of a pressure wavefield by itshydrophone; and the sensor 58 provides one or more traces thatcorrespond to one or more components of particle motion.

The goal of the seismic acquisition is to build up an image of a surveyarea for purposes of identifying subterranean geological formations,such as the exemplary geological formation 65. Subsequent analysis ofthe representation may reveal probable locations of hydrocarbon depositsin subterranean geological formations. Depending on the particularembodiment of the invention, portions of the analysis of therepresentation may be performed on the seismic survey vessel 20, such asby the signal processing unit 23. In accordance with other embodimentsof the invention, the representation may be processed by a seismic dataprocessing system that may be, for example, located on land or on thevessel 20. Thus, many variations are possible and are within the scopeof the appended claims.

Particle motion sensors are subject to relatively high noise levels,especially at low frequencies. A portion of this noise is attributableto vibration of the cable due to the pressure fluctuations and forces,including shear forces, applied to the outer surface of the streamerthat are generated by a turbulent flow in a boundary layer that existsbetween the outer surface of the streamer 30 and the water through whichthe streamer 30 is towed. More specifically, referring to FIG. 2 (whichdepicts an exemplary segment of a streamer 30), a streamer 30 inaccordance with embodiments of the invention may be towed through thewater, which creates turbulences 112 in a boundary layer that surroundsthe outer skin of the streamer 30. These turbulences will createpressure fluctuations and apply forces to the outer surface of thestreamer, which excite vibrations (longitudinal, transversal andtorsional) in the streamer. As depicted in the corresponding absolutevelocity profile 115 (depicting the velocity relative to the ambientwater), the velocity of the water decreases with the distance away fromthe outer surface of the streamer 30.

The turbulences 112, because they generate vibration in the cable, arepotential noise sources that may adversely affect the quality of themeasurements that are acquired by particle motion sensors 100 of thestreamer 30. The particle motion sensors 100 may be contained in aninner cable 111 of the streamer 30. Depending on the particularembodiment of the invention, the particle motion sensors may be particlemotion sensing components of multi-component sensors or may be standalone sensors.

The elastic wave speed in a fluid is high due to the relatively highbulk modulus of the fluid. This characteristic is used, in accordancewith embodiments of the invention described herein, to average theturbulences 112, which will then limit the vibration of the core causedby these turbulences 112, and therefore limit the noise recorded by theparticle motion sensor. More specifically, as described herein, thestreamer 30 has a fluid containing layer that sums the positiveamplitude pressure pulses with the negative amplitude pressure pulses toprovide resulting smaller total pressure amplitude(s), such that theexcitation of vibration is smaller, which is sensed as noise by theparticle motion measurements. As a result, the fluid averaging limitsflow noise pick-up for the particle motion measurements.

As a more specific example, in accordance with embodiments of theinvention, the streamer 30 has a fluid containing layer that moves withthe sensitive inner cable 111 and surrounds the cable 111. Because thefluid containing layer is moving together with the inner cable 111 asthe streamer 30 is towed, there is no relative inline flow movementbetween the fluid within the fluid containing layer and the sensitivepart of the inner cable 111. Due to this arrangement, the fluidcontaining layer averages the pressure fluctuations 112 and greatlyreduces inner cable vibration to suppress noise that is otherwise sensedby the particle motion sensors 100.

The forces, including the shear forces, generated by the turbulences 112are applied to the outer skin of the streamer 30. As the outer skin isdisconnected from the inner cable by the fluid layer, only substantiallysmall (if any) components of these forces are transmitted to the innercable. As the level of vibration excitation from these forces is greatlyreduced on the inner cable, the level of vibration noise is also greatlyreduced.

Referring to FIG. 3, in accordance with some embodiments of theinvention, the inner cable 111 is a solid core cable, which containsvarious particle motion sensors, such as the exemplary particle motionsensors 100 that are depicted in FIG. 3. The inner cable 111 may includevarious other elements that are not depicted in FIG. 3, such as stressmembers, electrical cables, fiber optic cables and so forth.Additionally, in accordance with embodiments of the invention, the innercable 111 may include other types of seismic sensors, such ashydrophones.

In accordance with some embodiments of the invention, the particlemotion sensors 100 are embedded in a core material 101, such as athermoplastic material, which is either extruded or injection moldedinto a cable core. It is noted that the inner cable 111 depicted in FIG.3 is merely an example of one out of many possible embodiments of aninner cable that contains particle motion sensors. Thus, many variationsare contemplated and are within the scope of the appended claims.

For example, in other embodiments of the invention, the components ofthe inner cable 111, such as the particle motion sensors 100, may becontained within a tubing (a polyurethane tubing, as a non-limitingexample) which forms the outer layer of the cable. The inner space ofthe tubing may be filled with a plastic-type injection filling, such aspolyurethane, in accordance with some embodiments of the invention. Thecable core may also be a gel-filled streamer, in accordance with otherembodiments of the invention.

Turning now to more detailed examples of streamers that have fluidcontaining layers, FIG. 4 depicts a streamer 150 in accordance with someembodiments of the invention. The streamer 150 has a fluid containinglayer 164, which is formed in an annular space between the inner cable111 and the streamer's outer skin 160. As an example, the fluidcontaining layer 164 may contain a buoyant and non-reactive fluid, suchas water; and in general, the density of the fluid may be selected to benear the density of the inner cable 111, in accordance with someembodiments of the invention. In accordance with some embodiments of theinvention, water is neutrally buoyant and may be the preferred fluid. Ingeneral, the density of the fluid should be sufficiently close to thedensity of the inner cable to assure stability of the fluid layer. Asthe streamer as a whole should be neutrally buoyant, the inner cable andthe fluid has a density close to sea water in accordance with someembodiments of the invention. It is noted that the fluid containinglayer 164 may contain a fluid other than water (kerosene, for example)in accordance with other embodiments of the invention. Furthermore, asis the case for water, which is neutrally buoyant, the fluid of thefluid containing layer 164 does not necessarily have to be buoyant, asthe overall buoyancy of the streamer 150 may be adjusted by the innercable's buoyancy.

In addition to a fluid, the fluid containing layer 164 may contain anopen cell, or sponge-like, material 161 that is saturated with thefluid, in accordance with some embodiments of the invention. Thematerial 161 prevents the outer skin 160 from contacting the inner cable111, a contact which may introduce noise, and dampen the propagation ofwaves in the skin/fluid layer.

The fluid containing layer 164 radially extends between the exteriorsurface of the inner cable 111 and the inner surface of an outer skin160 of the streamer 150, in accordance with some embodiments of theinvention. In accordance with some embodiments of the invention, theouter skin 160 may be formed from a material (polyurethane, for example)that seals off the fluid containing layer 164 from the externalenvironment of the streamer 150. The fluid containing layer 164 averagesthe pressure fluctuations and forces generated by the turbulences 112that are present external to the outer skin 160. This averaging, inturn, lowers the amplitudes of the pressure fluctuations and forces andthus, suppresses, or attenuates, the vibration of the inner cable thatis otherwise sensed as noise by the particle motion sensors of the innercable 111. Therefore, the vibration caused by the turbulences that are“seen” by the sensitive part of the inner cable 111 are relatively low,and as a result, the particle motion sensors experience lower noiselevels. This averaging effect reduces the noise levels by minimizing theexcitations for the cable vibrations.

The outer skin 160, in a preferred embodiment, can be terminated at theconnectors of streamer 150. For practical reasons, as mechanicalrobustness during deployment and recovery of the streamer, it might bebeneficial to fix the outer skin to the inner core at some locationsalong the streamer. This can be done for example by clamping the outerskin to the inner core; or the outer skin can be glued or welded to theinner core, for example on protrusions of the inner core to keep theouter diameter constant.

It is noted that the fluid containing layer 164 does not significantlyreduce signal sensitivity for embodiments in which the bulk modulus ofthe inner cable 111 and the bulk modulus of the fluid containing layer164 are significantly high. Therefore, the net effect is an increasedsignal-to-noise ratio (SNR) for the particle motion measurements.

Referring to FIG. 5, in accordance with other embodiments of theinvention, a streamer 200 may be used in place of the streamer 150 (seeFIG. 4). Similar reference numerals are used in FIG. 5 to denote similarcomponents that are discussed above. Unlike the streamer 150 (FIG. 4),the streamer 200 includes an outer skin 204, which replaces the outerskin 160 of the streamer 150 (see FIG. 4) and allows fluid communicationbetween the fluid containing layer 160 and the environment outside ofthe streamer 200. As examples, the outer skin 204 may be perforated skinor a net. Through the “open” outer skin 204, the fluid containing layer164 is exposed to the surrounding marine environment of the streamer 200and thus, the fluid containing layer 164 is configured to receive waterfrom this environment. Due to its open cell or sponge-like design, thematerial 161 is constructed to retain water during the towed marineseismic survey to form a fluid averaging layer. Thus, when the streamer200 is subject to surrounding water, the cells of the material 161 fillup with the water, and the retained fluid volume in the material 161travels together with the streamer 200 and inner cable 111 in the towingdirection.

Because the fluid in the cells is stationary relative to the inner cable111, there is no turbulence or local flow effects, which occur on theouter surface of the inner cable 111. The pressure fluctuations 112 thatare outside of the material 161 are averaged within the fluid in thecells of the material 161, and as a result, the pressure and forcefluctuations that cause vibration of the sensitive part of the innercable 111 are reduced, as compared to a streamer that does not contain afluid containing layer.

Referring to FIG. 6, to summarize, a technique 300 may be used forpurposes of reducing noise caused by a turbulent boundary acting on atowed seismic streamer. The technique 300 includes providing a streamerthat has a cable that contains particle motion sensors, pursuant toblock 304. Pursuant to block 306, noise that is otherwise present in theparticle motion measurements is suppressed by a fluid containing layerthat surrounds and moves with the cable.

Other embodiments are contemplated and are within the scope of theappended claims. For example, referring to FIG. 7, in accordance withother embodiments of the invention, a tool 364 may be used in a boreholeapplication in a well 350 and may contain features that reduce noise. Inthis regard, the tool 364 may be, as a non-limiting example, asensor-based tool, that includes a sensor 367, such as anelectromagnetic (EM) coil, geophone, etc. As also depicted in FIG. 7, asa non-limiting example, the tool 364 may be conveyed downhole into awellbore 360 via a string 362 or other conveyance mechanism.

The tool 364 may be run into the wellbore 360 in a variety ofapplications, such as applications involved with the testing, drilling,completion or production phases of the well. Regardless of theparticular use of the tool experience a flow in the well, such as a flowof oil, water, drilling mud, etc., which causes vibration of the tool364. This vibration may cause noise to be introduced into themeasurements that are acquired by the sensor 367. However, unlikeconventional arrangements, the tool 364 contains an outer fluid layer368 that reduces the vibration of the sensor 364, lowers the noise thatis introduced into the sensor's measurements and generally improves thesignal-to-noise ratio (SNR) of the measurements.

It is noted that the well 350 may be a subsea or subterranean well,depending on the particular embodiment of the invention. Additionally,the wellbore 360 may be a vertical or lateral wellbore; and the wellbore360 may be uncased or cased. Thus, many variations are contemplated andare within the scope of the appended claims.

While the present invention has been described with respect to a limitednumber of embodiments, those skilled in the art, having the benefit ofthis disclosure, will appreciate numerous modifications and variationstherefrom. It is intended that the appended claims cover all suchmodifications and variations as fall within the true spirit and scope ofthis present invention.

What is claimed is:
 1. An apparatus comprising: particle motion sensors;and a streamer containing the particle motion sensors to be towed inconnection with a seismic survey, the towing of the streamer producing aturbulent flow and the streamer comprising: an inner cable comprising asolid material to circumscribe and extend along a longitudinal axis ofthe streamer and circumscribe at least one of the particle motionsensors such that the at least one particle motion sensor is embedded inthe solid material; and a fluid containing layer to surround the innercable to reduce noise otherwise sensed by the particle motion sensorsdue to the turbulent flow.
 2. The apparatus of claim 1, wherein thefluid containing layer comprises a material to be saturated with afluid.
 3. The apparatus of claim 2, wherein the material to be saturatedby fluid comprises an open cell material.
 4. The apparatus of claim 1,wherein the streamer comprises an outer skin to define an annular spacebetween the outer skin and the inner cable to contain a fluid.
 5. Theapparatus of claim 4, wherein the fluid containing layer comprises amaterial to be saturated with the fluid.
 6. The apparatus of claim 1,wherein the inner cable comprises a solid core cable.
 7. The apparatusof claim 1, wherein the fluid containing layer comprises a fluid and amaterial to be saturated with the fluid, and the streamer comprises anouter skin adapted to allow the fluid to be communicated to the materialfrom an environment external to the outer skin while the streamer isbeing towed.
 8. The apparatus of claim 7, wherein the fluid thatsaturates the material is substantially stationary with respect to thestreamer and attenuates the noise.
 9. The apparatus of claim 7, whereinthe outer skin comprises a perforated skin or a net adapted to allow thefluid to be communicated to the material from the environment externalto the outer skin.
 10. The apparatus of claim 1, wherein the solidmaterial comprises an injection molded material.
 11. The apparatus ofclaim 1, wherein the solid material comprises an extruded material. 12.A method comprising: providing particle motion sensors in a streamer toacquire particle motion measurements; embedding at least one of theparticle motion sensors in a solid core material of the streamer; andsuppressing noise otherwise acquired in particle motion measurements,comprising circumscribing at least one of the particle motion sensorswith a fluid containing layer that moves with the streamer, the fluidcontaining layer surrounding an inner cable to reduce noise otherwisesensed by the particle motion sensors due to a turbulent flow.
 13. Themethod of claim 12, wherein the act of surrounding comprises: forming anannular region in the streamer outside of the inner cable to contain afluid.
 14. The method of claim 13, wherein the act of surroundingfurther comprises: disposing a material in the annular region to besaturated with the fluid.
 15. The method of claim 13, wherein the act ofsurrounding further comprises surrounding the material with an outerskin that isolates the material from an environment outside of the skin.16. The method of claim 12, wherein embedding at least one of theparticle motion sensors in a solid core material comprises embedding atleast one of the particle motion sensors in a thermoplastic material.17. The method of claim 12, wherein embedding at least one of theparticle motion sensors in a solid core material comprises embedding atleast one of the particle motion sensors in a non-compressible material.